Neutron Porosity Based On One Or More Gamma Ray Detectors And A Pulsed Neutron Source

ABSTRACT

A method for pulsed neutron well logging of a subsurface formation, includes irradiating the formation with a plurality of bursts of neutrons of a group of selected durations; detecting gamma rays resulting from interaction of the neutrons during a group of selected time gates which contains at least some early and late gamma ray counts. The gamma rays are detected at at least two axially spaced apart locations from a position of the irradiating. In a computer, a ratio TRat is determined between the sum of detected gamma rays at a first axial spacing to the sum at a second axial spacing. A borehole correction is performed according to a function related to the ratio TRat before converting the ratio TRat to a hydrogen index or porosity of the subsurface formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

This is a continuation application of U.S. Non-Provisional applicationSer. No. 13/851,872 filed on Mar. 27, 2013, which claims the priority ofU.S. Provisional Application No. 61/616,446 filed on Mar. 28, 2012, bothincorporated herein by reference in their entireties.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

The invention relates generally to the field of measurements ofsubsurface formation properties using pulsed neutrons as an energysource. More specifically, the invention relates to determiningfractional volume of pore space (porosity) of subsurface formationsusing a pulsed neutron source and at least one gamma ray radiationdetectors.

Subsurface formation HI (hydrogen index) measurement using high energyneutrons as a measurement source has been used in well logging since atleast the 1950s. In case of no bound-water in the formation matrix (suchas shale), hydrogen atoms only appear in the pore space (oil or water).Thus, the formation hydrogen index is typically a measurement offormation porosity. Neutron source based porosity measurements known inthe art rely on the fact that the slowing down of neutrons, andtherefore the average distance travelled within the formations by theneutrons, is strongly dependent on the hydrogen content of theformation. The hydrogen content dependency is due to the fact thatneutrons can incur a very large energy loss in a single elasticscattering event with a proton (a hydrogen nucleus). In its simplestform, neutron based porosity measurement can be performed using aneutron source and a detector axially spaced from the neutron source. Ifthe axial spacing of the detector from the source is chosenappropriately, then the neutron flux at the detector location willdecrease monotonically with increasing formation hydrogen content. Asone possible alternative, the neutron detector can be replaced by agamma-ray detector, since the flux of neutron induced gamma-rays isrelated to the neutron flux.

Early versions of neutron-based porosity measurement instrumentsincluded those having a single gamma-ray detector (e.g., aGeiger-Mueller counter) with a radioisotope-based neutron source (e.g.,²⁴¹AmBe, ²³⁸PuBe). Such instruments may be referred to as“neutron-gamma” instruments. Correspondingly, instruments using aneutron detector (e.g., a ³He proportional counter) may be referred toas “neutron-neutron” instruments. Traditionally, the term “neutronporosity” typically means a neutron-based porosity measurement using a²⁴¹AmBe source and “neutron-neutron” instruments. The following termsare defined in order to differentiate this work from the traditional“neutron porosity”. “Neutron-neutron porosity” may be defined as neutronporosity based on a neutron source and neutron detectors. Similarly,“neutron-gamma porosity” may be defined as neutron porosity based on aneutron source and gamma ray detectors, which is the scope of thisinvention.

Both neutron-neutron instrument measurements and to an even largerextent neutron-gamma instrument measurements are strongly affected by amultitude of environmental effects. Most, if not all open-hole neutrontools used at the present time are neutron-neutron measurements based onthe detection of the thermal and/or epithermal neutron flux at one ormore neutron detectors.

It can be more difficult to measure formation HI based on gamma raydetectors as compared to using neutron detectors. In addition to otherphenomena, gamma ray detectors measure the gamma rays from neutron“capture” interaction (i.e., capture of a thermal neutron by a nucleusof certain atoms having large “neutron capture cross section” andsubsequent emission of a gamma ray) in the formation, wellbore or theinstrument itself. Capture gamma ray measurement is therefore anindirect measurement the presence of neutrons. The physics ofneutron-neutron porosity only involves neutron transport from the sourceto the neutron detector. The physics of neutron gamma porosity involvesboth neutron and gamma ray transport, so that such physics are morecomplex. Thus, neutron-gamma porosity may have more environmentaleffects which may be more difficult to interpret.

Notwithstanding the additional complexity in interpretation there may beadvantages associated with measuring neutron-gamma porosity. The countrate of a gamma ray detector can be more than 1 order of magnitudehigher than a ³He neutron detector. The depth of investigation (lateraldistance from the wellbore wall into the formation) of a neutron-gammameasurement may be deeper than that of a neutron-neutron measurement.The energy of a gamma ray from a neutron capture event is normally inthe million electron volt (MeV) range, which means such gamma rays cantravel a longer distance than a thermal neutron before absorption. Ascintillation type gamma ray detector can also provide gamma rayspectroscopy and inelastic neutron scatter-related measurements, which athermal or epithermal neutron detector cannot. The foregoing featuresmake neutron-gamma porosity very appealing. Thus is it desirable to havean improved neutron-gamma porosity instrument.

SUMMARY

A method for pulsed neutron well logging of a subsurface formation,includes irradiating the formation with a plurality of bursts ofneutrons of a group of selected durations; detecting gamma raysresulting from interaction of the neutrons during a group of selectedtime gates which contains at least some early and late gamma ray counts.The gamma rays are detected at at least two axially spaced apartlocations from a position of the irradiating. In a preferred embodiment,a weighted sum of the numbers of gamma rays detected in each of the timegates is calculated. A ratio of the weighted sum of detected gamma raysat a first axial spacing to the weighted sum at a second axial spacingis determined. The ratio is used to determine a hydrogen index of thesubsurface formation.

Other aspects and advantages will be apparent from the description andclaims which follow.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an example neutron-gamma well logging instrument using a“pulsed” neutron source.

FIG. 2 shows a graph of an example of detector impulse response.

FIG. 3 shows a graph of detector thermal ratio (TRat) as a function ofthe starting time of the time gate.

FIGS. 3A and 3B show, respectively, the calculated time dependentspectra of the two detectors of FIG. 1 at different spacings, inconditions essentially the same as the ones used to generate the curvesshown in FIG. 3.

FIGS. 4A and 4B show graphs of TRat as a function of formation hydrogenindex (HI) for different gate starting times after a neutron “burst.”

FIG. 5 shows a graph of examples of the neutron burst scheme withdifferent burst length.

FIG. 6 shows a graph of estimated HI (x-axis) as a function of wellborefluid salinity (y-axis).

FIG. 7 shows an example neutron burst scheme to achieve good statistics,early gamma ray counts information for neutron-gamma porositymeasurement, and long wait time for neutron capture cross sectionmeasurement.

FIG. 8 shows a graph of early TRat based on the neutron burst schemeshown in FIG. 7 as a function of formation HI.

FIG. 9 shows a graph of TRat as a function of formation HI for wellboreconditions 8 inch diameter wellbore, 5.5-inch diameter casing cementedtherein, 4.95-inch internal casing diameter, API class H cement betweenthe wellbore and the casing exterior, and fresh water in the wellbore.

FIG. 10 shows a graph of TRat₀ vs. TRat in a 10-inch diameter wellborewith 5.5 inch casing, 4.95-inch casing ID, class H cement, andcentralized casing. The wellbore is filled with 10 different fluids:fresh water, salt water (at NaCl concentrations of 50, 100, 150, 200,250 ppk respectively), methane gas (0.15 and 0.25 g/cm³), diesel fueland light oil (0.65 g/cm³). The ten solid lines are linear fits for theforegoing ten different borehole fluids. The dashed line is a 45-degreediagonal line, where TRat is equal to TRat₀.

FIG. 11 shows a graph of the difference between the TRat₀ and estimatedTRat₀ based on linear fits as a function of TRat₀.

FIG. 12A shows a graph for verifying the TRat₀ linear approximation infourteen different wellbore and casing sizes (see Table 1 for details).Each wellbore can be filled with ten different borehole fluids. Thetotal number of simulations is 36×14×10=5040. The graph shows theresiduals in TRat₀ as a function of TRat₀.

FIG. 12B shows the residuals in FIG. 12A in limestone-equivalent HI as afunction of limestone-equivalent HI.

FIGS. 13A and 13B show different examples of residuals according to thecorresponding functions of FIGS. 12A and 12B, respectively.

FIGS. 14A and 14B show graphs applying the TRat₀ linear approximation tosingle detector (near in FIG. 14A and far in FIG. 14B) count rates. Thetiming gate is the total decay time except for a small delay after eachburst of the burst sequence shown in FIG. 7. The timing gate is the samewith respect to the early TRat timing gate used shown in FIG. 8.

FIG. 15 shows a graph verifying the TRat₀ linear approximation for theearly TRat.

FIGS. 16A and 16B show, respectively applying the TRat₀ linearapproximation to single detector count rates, near in FIG. 16A and farin FIG. 16B. The timing gate is from 130 μs after the last burst in FIG.7 to the end of the detected gamma ray decay.

FIG. 17 shows a graph for verifying the TRat₀ linear approximation for alate TRat, with the timing gate from 130 μs after the last burst in FIG.7 to the end of the detected gamma ray decay.

FIG. 18 shows an example neutron burst timing sequence.

FIG. 19. Shows how to compute TRat from gamma ray counts measured inselected time windows.

FIG. 20 shows example time gates with reference to the neutron bursttiming.

FIG. 20A shows an example process flow for use with a practical welllogging instrument.

FIG. 21 shows a flow chart of an example conversion of TRat intohydrogen index.

FIG. 22 shows a flow chart of an example conversion of individualdetector counts into hydrogen index.

FIG. 23 shows an example computer system that may be used in someembodiments to implement example methods according to the presentdisclosure.

DETAILED DESCRIPTION

FIG. 1 shows an example “neutron-gamma porosity” well logging instrument10. The measurement components of the instrument 10 may be disposed in ahousing 12 shaped and sealed to be moved along the interior of awellbore. The pulsed neutron well logging instrument 10 may, in a formhereof, be of a type described, for example, in U.S. Pat. No. 5,699,246.

The instrument housing 12 contains a pulsed neutron source 14, and twoor more gamma ray detectors 18, 20 at different axial spacings from thepulsed neutron source. The pulsed neutron source 14 (hereinafter“source”), when activated, will emit controlled duration “bursts” ofhigh energy neutrons (approximately 14 MeV, and which may be emittedisotropically). One example of a pulsed neutron source is described inU.S. Pat. No. 5,293,410 issued to Chen et al. and incorporated herein byreference.

Shielding 16 may be interposed between the source 14 and the axiallyclosest detector (e.g., 16) to reduce the effects of direct neutroncommunication between the source 14 and the detectors 18, 20. Thedetectors 18, 20 may be scintillation counters each coupled to arespective counter or pulse height analyzer (not shown separately).Thus, numbers of and, with the use of a pulse height analyzer, energy ofdetected gamma rays may be characterized at each of a plurality ofdistances from the source 14.

The gamma ray detectors 18, 20 may detect gamma rays arriving at thedetector as a function of time. There are two principal mechanisms,through which a neutron-induced gamma ray can be generated. One isneutron inelastic scattering, which can be triggered only by “fast”neutrons (with energy above approximately 1 MeV, the exact energythreshold depending on the type of nucleus). The other is throughneutron capture, which can be triggered primarily by thermal neutrons(with energy around 0.025 eV at room temperature) or epithermal neutrons(with energy from about 0.4 to 100 eV) being absorbed into a susceptiblenucleus, as non-limiting examples, chlorine, boron and cadmium. When thesource 14 is activated, the gamma rays arriving at the detectors 18, 20may be generated through both mechanisms because the source keepsemitting fast neutrons which can slow down to epithermal or thermalalmost instantly (relative to the acquisition system timing). When thesource 14 is switched off, the gamma rays arriving at the detectors 18,20 may only be generated by epithermal or thermal neutron capturebecause no new fast neutrons are emitted into the wellbore andformations. Thus, the measured gamma ray flux at the detectors 18, 20during the source off time is an indirect measurement of epithermal andthermal neutrons. Such indirect measurement can be used to provideformation hydrogen index (HI) measurement.

A well logging instrument including a scintillation detector typeradiation counter is ordinarily used in a procedure to make measurementsof properties of subsurface Earth formations penetrated by a wellbore.The wellbore is drilled through the formations. The wellbore may befilled with liquid called “drilling mud” during the drilling and welllogging procedure, or some form of brine or other completion fluid afterwellbore construction is completed. The well logging procedure includeslowering the well logging instrument into the wellbore. The instrumentmay be attached to one end of an armored electrical cable. The cable isextended into the wellbore by a winch or similar spooling device tolower the instrument into the wellbore. The winch may then be operatedto withdraw the cable from the wellbore while various sensors (to befurther explained) in the instrument make measurements of variousproperties of the formations penetrated by the wellbore. Electricalpower may be transmitted along the cable from the surface to operate theinstrument. Signals corresponding to the measurements made by thevarious sensors in the instrument (explained above with reference toFIG. 1) may be transmitted along the cable for recording and/orinterpretation in a recording unit at the Earth's surface, or in acomputer system as will be explained with reference to FIG. 23.

The present example of the well logging instrument may be an instrumentthat makes measurements corresponding to selected properties of theEarth formations based on spectral analysis of detected gamma rays. Suchinstruments include a housing in which is disposed certain electroniccircuitry, to be further explained below. The housing may or may notinclude a backup pad or arm that is biased to one side of the instrumentto urge the other side of the instrument into contact with the wall ofthe wellbore. The other side of the instrument may or may not include atungsten or similar high density skid or pad in which is disposed asource radiation, which may be a pulsed neutron source as explained withreference to FIG. 1 above. Although the example instrument includesvarious components disposed in a skid or pad, in other examples, thecomponents may be disposed entirely within the instrument housing asshown in FIG. 1.

One or more radiation detectors (e.g., as explained with reference toFIG. 1) including a scintillation detector crystal optically coupled toa photomultiplier may be disposed in the pad. A controllable highvoltage power supply is coupled to the photomultiplier to enable photonsapplied thereto to be converted to voltage pulses as will be familiar tothose skilled in the art. The voltage output of the high voltage powersupply can be controlled by a controller forming part of the circuitryto cause the high voltage supply maintain a suitable voltage on thephotomultiplier.

While the example conveyance of a well logging instrument uses armoredelectrical cable, the foregoing is not intended to limit the scope ofinstrument conveyance according to the disclosure. Any known means ofconveyance may be used in other examples, including, without limitation,as part of a drill string as a logging while drilling (LWD) instrument,conveyed by coiled tubing or slickline.

In order to explain the present example method, the impulse response ofone of the gamma ray detectors (e.g., 18 and 20 in FIG. 1) may beobserved in FIG. 2, which shows a calculated time dependent count ratespectrum (can be measured by a multichannel scaler (MCS) coupled to aphotomultiplier/scintillation counter type gamma ray detector)corresponding to a neutron burst (e.g., from the source 14 in FIG. 1) attime=0, which essentially represents the detector impulse response. Attime=0, one may observe a “spike”, which corresponds to gamma raysgenerated predominantly by fast neutron inelastic scattering and to amuch lesser extent by epithermal/thermal neutron capture events. Aftertime=0, when the source is inactive, the number of detected gamma raysdecays close to exponentially.

A detector thermal ratio (TRat) may be defined as the ratio of the sumsof the time spectra in two detectors within selected time gates or timewindows with respect to the neutron burst. TRat may be a function of thetime gates (see, e.g., U.S. Patent Application Publication No.2011/0213555, incorporated herein by reference in its entirely). Becausethe time spectra decay substantially exponentially, the starting time ofthe time gate has a greater effect than the end of the time gate on theTRat response. In order to evaluate the TRat response as a function ofthe starting time of the timing gate, Monte Carlo simulation may be usedto model several impulse responses and to compute TRat by varying thestarting time of the timing gate and fixing the end time of the timinggate at infinity. The conditions for the simulations used in the presentexample include 20 porosity unit (p.u.) sandstone filled with 200-ppk(parts per thousand) salt water disposed in the pore spaces thereof. Awellbore drilled through the formation may be 8 inches in diameter andhas inserted and cemented therein a 5.5-inch outside diameter (O.D.)steel casing (having 4.95-inch internal diameter—ID) and wherein thecement disposed between the wellbore wall and the exterior of the casingis American Petroleum Institute (API) class H cement. The wellbore isconsidered to be filled with three different borehole fluids separately,fresh water, 100-ppk brine, and 200-ppk brine (sodium chloride solutionin water).

The three curves, 26, 28, 30, respectively, in FIG. 3 show modeled TRatresponse with respect to gate starting time for the above describedwellbore conditions and corresponding to the foregoing three differentborehole fluids. The differences between the three curves 26, 28, 30 areonly due to the different borehole salinity, because all the otherconditions are exactly the same. The borehole salinity effect in TRat isvery small when the timing gate starts earlier than 20 μs after theneutron burst, and will increase as the timing gate starts later afterthe neutron burst.

This phenomenon does not only appear to exist for one formationcondition, it appears to exist for many known formation conditions.FIGS. 4A and 4B show, respectively, TRat calculations with timing gatesstarting at 10 or 130 μs after the neutron burst for a large number offormation and borehole conditions. The calculations are for sandstoneformation with porosities of 0, 2.5, 5, 10, 20, and 40 p.u.,respectively. The symbols indicate different formation connate watersalinities, and the different colors indicate different wellbore fluidsalinities. The solid lines are 3^(rd) order polynomial fits through thefresh water data in both the formation and the wellbore.

The TRat with timing gate starting at 10 μs after the burst (called the“early TRat), shown in FIG. 4A) has almost no wellbore salinity effectin all modeled formation conditions, and the TRat with timing gatestarting at 130 μs after the burst (called the “late TRat”, shown inFIG. 4B) has a large wellbore fluid salinity effect. The total salinityeffect in the late TRat depends on the formation porosity and salinityand it is very difficult to correct for wellbore salinity. This isbecause the wellbore salinity may not be well known, the correction islarge relative to the measurement of TRat and is non-linear. Thus, inthe present example, the wellbore salinity effect may be accounted forby using the early TRat. In addition, the early TRat may be expected tohave better statistical precision than the late TRat.

The reasons for this phenomenon are quite complex. They involve thecomplex process of fast neutrons slowing down and being captured as afunction of time in the existing instrument and wellbore geometry. Thereis not believed to be a theoretical analytical solution and obtaining anapproximate solution may be challenging. One possible explanation may beas follows.

Consider the whole process of emission of high energy neutrons and thesubsequent detection of gamma rays as consisting of two processes.First, fast neutrons from the source slow down to an energy just abovethe thermal energy, at which point the wellbore salinity does not yethave a significant impact on the detected gamma rays. At this point, theneutron population in the formation and wellbore does not dependsignificantly on the wellbore salinity. Second, the foregoing slowedneutrons keep losing energy by scattering and eventually become thermalneutrons, which can then be captured by certain nuclei and producecapture gamma rays. In the second process, higher borehole salinity andthus higher chlorine content increase the neutron capture probabilityand the concomitant capture gamma ray production. Right after theneutron source burst or at a very early time after the burst, the fastneutrons have just been slowed down to epithermal or thermal energiesand the borehole salinity does not yet have a significant impact on theneutron flux distribution. If the gamma ray counts from this time toinfinity are integrated, the integrated number of gamma ray countsshould be proportional to the total neutron population in the “sensitivevolume” (the volume in which, if a neutron is captured, the resultinggamma ray can register in the detector) because all neutrons willeventually be captured at some time. This is based on the assumptionthat there are no neutrons moving into or out of the “sensitive volume”.

In reality, thermal neutrons diffuse. The diffusion takes the form ofthermal neutrons moving from regions of high neutron density to regionsof lower neutron density. High borehole salinity will strongly capturethermal neutrons and reduce the local neutron density. Differentborehole salinities will cause changes in neutron diffusion into and outof the “sensitive volume” and thereby change the total gamma ray countsat the individual detectors. However, the diffusion difference caused byborehole salinity may be independent of the detector spacing. Therefore,after determining the count rate ratio using an early timing gate, theborehole salinity effect can be canceled.

The explanation above is substantially simplified. In reality, there isnot a clear demarcation between the first and second processes in termsof both time and energy. The borehole salinity effect cannot be canceledperfectly. However, it can be reduced to below 1 p.u., as shown in FIG.4A, which may be acceptably small for formation evaluation applications.

In order to explain how to achieve a detector count ratio (TRat)substantially free of wellbore salinity with various neutron burstschemes other than the impulse scheme, the following description willfocus on the impulse response further to identify the basic componentswhich are required to compensate the wellbore salinity. FIGS. 3A and 3Bshow, respectively, the calculated time dependent spectra of the twodetectors (18, 20 in FIG. 1) at different spacings, in conditionsessentially the same as the ones used to generate the curves shown inFIG. 3. Apparently, the wellbore salinity effect in the detector countrate time spectra reverses sign before and after around 70 μs aftertime=0, when the neutrons are generated, for both detectors. An “earlygamma ray count” may be defined as a detected gamma ray event in thedetector at the time t, caused by the capture of a neutron generated atto, where (t−t₀)<70 μs. For “late gamma ray count” the time different(t−t₀) is greater than 70 μs. An “early time gate” may be defined as atime gate which contains at least some early gamma ray counts. An “earlytime gate” may also contain some late gamma ray counts due tocontamination, which is hard to avoid in reality. A “late time gate” maybe defined as a time gate which contains late gamma ray counts but noearly gamma ray counts. Higher wellbore salinity will cause the detectedearly gamma ray counts to be higher, and cause the detected late gammaray counts to become lower. The detector count rates may be summed inone or more “early time gates” and summed in one or more “late timegates.” The detector count rates may be summed in a plurality of earlyor late time gates with different weights applied to the respectiveearly and late time gates. The foregoing summing may be performed forboth detectors and a ratio may be calculated to calculate TRat. By finetuning the early and late time gates, and the relative weightsassociated with them, it may be possible to compensate the wellboresalinity effect and determine a TRat substantially free of wellboresalinity effect. The time gate, which is used in FIG. 4A, which extendsfrom 10 μs after the neutron burst to infinity, shows a simple example.the example of FIG. 4A shows results of having an early time gate thatextends from 10 μs after time=0 to 70 μs after time=0, and contains onlyearly gamma ray counts, and a late time gate, which extends from 70 μsafter time=0 to infinity, and contains only late gamma ray counts, withthe same weights for both early and late time gates. Using the sameprocedure it may be possible to compensate the wellbore salinity effectof the sum of individual detector count rates in selected time gateswith proper weights, without taking a detector ratio.

A practical consideration is the gamma ray counting statistics. Toachieve reasonable statistical precision, as many neutrons as theneutron source can produce are imparted into the wellbore and thesurrounding formations. However, the neutron output is practicallylimited when the source is “on” or the burst time is relatively shortand the wait time between bursts is relatively long. Neutron generationefficiency is related to the duty factor (burst duration/total time)with better neutron generation efficiency corresponding to greater dutyfactors. In order to impart more neutrons, it may be insufficient onlyto turn on the neutron production for a typical duration, e.g., 1 μs andwait for a relatively long time until the subsequent burst. A longduration neutron burst may be more favorable for high statisticalprecision. For example, some pulsed neutron generators known in the artcan provide 20 μs, 60 μs, or even a few hundred microsecond bursts inorder to enhance the statistical precision of the measurements made. Insuch case, the time gate from the end of the neutron burst to 70 μsafter the end of the neutron burst does not only contain early gamma raycounts, but also contains some late gamma ray counts. This is becausesome of the gamma ray counts at 70 μs after the end of the neutron burstare induced by neutrons that were generated during the early part of theneutron burst. Thus, the difference between the time the gamma rayregistered in the detector and the time the neutron is generated may bemore than 70 μs. These are not early gamma ray counts but the late gammaray counts. Thus, some of the early time gate may be contaminated bylate gamma ray counts. The longer the neutron burst, the more late gammaray contamination there is in this time gate. Additionally, some of theearly gamma ray counts can be obscured by the neutron burst itself.During neutron burst “on” time, fast neutrons exist in the system andcan induce gamma rays by inelastic scattering. Inelastic gamma raycounts registered in the detector cannot be separated in time from someof the early gamma ray counts corresponding to source neutrons, whichare generated earlier in the same neutron burst. On the other hand, thetime gate 70 μs after the end of the neutron burst only contains lategamma ray counts and is not contaminated by any early gamma ray counts.Another important consideration is the formation neutron capture crosssection measurement (Sigma measurement), which can be provided by a longwait time after a neutron burst. Thus, one cannot cut the long wait timetoo much to improve the duty factor of a short neutron burst to achieveboth early timing information and precision. While typical burst lengthsare listed above, there is a wide variety of burst lengths from a fewmicroseconds to hundreds of microseconds that may be used in variousexamples.

FIG. 5 shows a few examples of neutron burst schemes that may be used insome implementations. The burst lengths are 20, 30, 40, and 50 μsrespectively, which are followed by a long wait time. The early TRat iscomputed for the four burst schemes from the right after the burst tothe end of neutron decay (about 1000 μs). This time gate contains boththe early and late gamma ray counts. With different burst lengths, therelative numbers of early and late gamma ray counts varies. Theestimated HI computed from early TRat are shown in FIG. 6 as a functionof wellbore salinity. As may be observed in FIG. 6, the longer theneutron burst is, the more the early gamma ray counts become obscuredwithin the burst gate, and the larger the apparent wellbore salinityeffect is. A 50-μs duration neutron burst may introduce a −0.025 HIerror out of a total 0.2 HI, with 250-ppk wellbore fluid salinity. Onthe other hand, a longer neutron burst has better statistical precisiondue to the higher duty factor (2%, 3%, 4% and 5%, respectively for the20, 30, 40, and 50-μs burst lengths). The wellbore salinity effectassociated with any particular burst scheme with a long neutron burstcan be compensated by balancing the weight of the early and late gammaray counts, which will decrease the statistical precision.

In order to have both acceptable early gamma ray count information andgood precision, an example neutron burst scheme is shown in shown inFIG. 7. A sequence of a selected number of neutron bursts with a lengthof, for example, 20 μs, may be separated from each other by a short waittime of, for example, 30 μs to obtain the early gamma ray countsinformation, and a much longer wait time after the end of the selectednumber of bursts. In this way, one can irradiate the formation withsufficient neutrons (the burst duty factor may be 20% or even higher),and at the same time the early gamma ray counts information may beobtained with sufficient precision to determine Trat. The long wait timemeasurement may also available to determine the formation capture crosssection.

The early TRat may be calculated by summing over the total capture timegate (when the neutron burst is off, except for a small delay afterevery burst, this time gate is illustrated in FIG. 20) and plotted asshown FIG. 8. The 30-μs short wait time after every neutron burstcontains the early gamma ray count information without excessive lategamma ray count contamination. It is possible to adjust the number ofshort neutron bursts in any example burst scheme to fine tune the amountof early gamma ray counts relative to the late gamma ray counts. Thepresent example may use 23 neutron bursts in total. The apparentwellbore salinity effect is small, and the precision of TRat may beexpected to be good because of the selected sequence of neutron bursts.The long wait time measurements for formation capture cross sectionmeasurement may also available. The use of a sequence of short pulsesseparated by short decay intervals is described, for example, in U.S.Pat. No. 6,703,606 issued to Adolph.

FIG. 7 shows just one example of a neutron burst scheme usable with thepresent example. Following the same principles explained above, thoseskilled in the art can readily derive other neutron burst schemes withburst lengths longer or shorter than the 20 μs used in the presentexample, or the short wait time may be longer or shorter than the 30 μsused in the present example. Similar neutron burst schemes have beenused for neutron porosity measurements but it is not believed that aburst scheme such as the one described above has been used forneutron-gamma porosity measurement. Neutron-gamma porosity measurementsknown in the art are believed to be made from TRat measurements onlyusing longer burst lengths. Although certain pulsed neutron instrumentsuse a single short-duration burst to measure wellbore neutron capturedecay, the early-time TRat was not known to be used for a porositymeasurement. A single short burst can provide the early time gatewithout too much late gamma ray count contamination, which theoreticallycan be used to combine with some late time gate to compute a TRat freeof wellbore salinity effect. However, such a TRat may have anunacceptably poor statistical precision due to the low number of gammaray counts in the single short burst decay period.

As described above, some of the early gamma ray counts can be mixed withinelastic gamma ray counts inside the duration of a neutron burst. Inreality, a neutron burst cannot be ended instantaneously. It is possiblethat after the end of a neutron burst, there may be still some inelasticgamma rays being generated and detected. If a time gate after a neutronburst is extended early enough or even into the neutron burst, someinelastic gamma ray counts may contaminate the gamma rays detectedduring such time gate. The fast neutron flux, which induces theinelastic gamma rays, depends on not only the hydrogen nuclear densitybut also the presence of atomic nuclei which can scatter neutronsinelastically. As long as the inelastic gamma ray contamination issmall, for example, than 5% to 10% of the total gamma ray counts in allthe time gates, which are used to compute TRat, one can still have aTRat substantially free of wellbore salinity effect and provide a goodformation hydrogen index measurement.

The above examples show that it may be possible to optimize the neutronburst timing scheme and the time gates to substantially reduce thewellbore salinity effect.

However, wellbore salinity is only one of a plurality of wellboreconditions that may be accounted for in neutron-gamma porositymeasurement. Since the physics involved in neutron-gamma porositymeasurement are quite complex, the wellbore contaminations of TRat mayalso depend on many formation conditions, for example, porosity,formation fluid type, formation lithology (formation mineralcomposition), connate salinity, as non-limiting examples. In order toaccount for substantially all the wellbore effects, it is desirable toseparate the wellbore and formation responses. In this way, the wellboreand formation effects on the detected gamma rays can be treatedseparately for the determined porosity, and the wellbore and formationenvironmental corrections may be independent of each other. This may bepossible based on a TRat₀ linear approximation, which will be introducedbelow.

FIG. 9 shows the TRat response at one set of wellbore conditions (8wellbore diameter, 5.5 inch casing OD, 4.95 inch casing ID, class Hcement, casing centered in the wellbore) for 36 different formationconditions (see the figure captions for details). TRat at the foregoingwellbore conditions may be defined as TRat0. The foregoing may beforward modeled as to what a neutron-gamma instrument would measuredirectly, and such forward modeling results can be obtained using aMonte Carlo code. TRat₀ is thus a formation property and is independentof wellbore conditions. TRat₀ is related to the formation neutron-gammacross sections. The TRat0 linear approximation is that the TRat (toolmeasurement) at any wellbore condition is a linear function of TRat₀, asshown in Equation 1

TRat=f ₁(BH)·TRat₀ +f ₂(BH)   (1)

Where, the gain (f₁) and offset (f₂) are functions of wellboreconditions, and are independent of formation conditions. Thus, thewellbore (gain and offset) and formation responses (TRat₀) may beseparable and may be processed separately. This may dramaticallysimplify the interpretation. The detector ratio TRat is a non-linearfunction of formation hydrogen index (or porosity). By separating theformation and wellbore response, one can perform borehole correctionsbefore converting the TRat to HI (or porosity) to avoid a non-lineartransformation.

In order to verify how good the TRat₀ linear approximation is, more than5000 Monte Carlo simulations were generated for 36 different formationconditions in various wellbore conditions. FIG. 10 shows how well thisapproximation works for a 10 inch diameter wellbore with the same casingand cement type but filled with 10 different wellbore fluids. There are10 black solid lines in the left panel of FIG. 10, which are the linearfits for 10 borehole fluids. TRat data well fit a linear function ofTRat₀ in the 10 borehole conditions. Since the wellbore salinity effecthas been substantially eliminated in TRat, there are 6 lines alltogether for different wellbore fluid salinities from fresh to 250 ppk,which cannot easily be distinguished from each other visually. The linefor diesel fuel is also very close to the 6 water lines. A line forlight oil is further to the left. The lines for two gas-filled wellboresare well separated at the left from the corresponding lines forliquid-filled wellbores. All the 10 different borehole conditions onlychange the gain and offset, but not TRat₀.

FIG. 11 shows residuals in the estimated TRat₀ based on linear fittingas a function of TRat₀. Equation 2 shows how to convert the TRat at anywellbore condition to an estimated TRat₀, which is an inverse model. Thegain and offset (a and b) are functions of wellbore conditions. Equation1 is a forward model. The residuals are small except for 0 p.u.sandstone and 100 p.u. (fresh) water. A trend in the residuals as afunction of TRat₀ does not seem to be observable, which indicates thatthere is no need for a higher order term. Overall, the linearapproximation may be acceptable for 10-inch wellbore diameter. Theresiduals may be converted to porosity units and verified at allsimulated wellbore conditions as follows.

TRat₀ =a(BH)·TRat+b(BH)  (2)

TABLE 1 14 wellbore diameter and casing diameter combinations. (Units:inch) BSIZ 6 6 6 8 8 8 8 8 10 10 10 10 12.25 12.25 CSIZ 5.5 5.5 4.5 5.57 7 7 7 5.5 5.75 6 6.25 5.5 9.625 CID 4.95 4.67 4 4.95 6.538 6.366 6.0945.92 4.95 4.95 4.95 4.95 4.95 8.535

BSIZ represents wellbore diameter, CSIZ represents casing OD and CIDrepresents casing ID in Table 1. Monte Carlo modeling may be used tosimulate the instrument response of the 36 formation conditions in 14different borehole size/casing size combinations, which are shown inTable 1 above. For each set of borehole size/casing size conditionssimulations were performed for 10 different wellbore fluids. The totalnumber of simulations performed was 36×14×10=5040. The foregoingmodeling database covers a very wide range of realistic formation andwellbore environmental conditions. FIG. 12A shows how well the TRat₀linear approximation appears in the database of all the foregoing 5040simulations in terms of limestone-equivalent HI. The foregoing is thedifference between the HI converted from TRat₀ and estimated TRat₀. Thusboth TRat₀ and the estimated HI may be based on the fit (shown in FIG.9) of limestone fresh water porosity. As may be observed in FIG. 12A,the accuracy of the TRat₀ linear approximation is within +/−2 p.u. forthe whole simulation database, with some exceptions. Part of the sourceof errors may come from Monte Carlo statistical uncertainties. Theaverage errors in the whole database are well below 2 p.u. 100 p.u.fresh water has a very large error, but it is not a condition likely tobe encountered when measuring common geologic formations. The H&H shale,which is an average of numerous dry clay core samples, also has a largeerror, partially due to small HI sensitivity at high porosity. The 20%clay-filled sandstone has a ±4 p.u. error over the whole database.Overall, the TRat₀ linear approximation appears to be accurate in manyordinarily encountered wellbore conditions. Thus, the separation ofwellbore and formation response appears to be possible.

Given the foregoing, the wellbore effect compensation may be easy toperform. For known wellbore conditions, such as wellbore diameter,casing OD, casing ID, tubing, double casing, cement, and so on, it maybe possible to characterize the gain and offset (a and b in Equation 2).In order to do so, one can either perform measurements or simulations orboth to study the response. It may not be necessary to use a largenumber of different formation conditions because the gain and offset areindependent of the formation conditions. For unknown wellboreconditions, such as eccentered casing, instrument standoff, wellborewashout, depending on how big those effects are, it may be possible touse the available measurements to determine a correct gain and offset,or provide an accuracy tool planner (forward model) to the experienceduser to determine the correct gain and offset case by case.

The TRat₀ linear approximation may also work for open hole conditions.The instrument response was simulated for a 5-inch diameter uncasedwellbore (open hole) with 0 or 0.5 inch standoff (separation of theinstrument housing from the wellbore wall in a wellbore filled withfresh water, and saline solution (100 ppk or 250 ppk), bentonite mud,hematite mud, or barite mud. In open hole, the TRat₀ was defined as theTRat in fresh water-filled wellbore without any standoff. FIG. 13A showsthe accuracy of this approximation in the same way as FIG. 12A.Residuals are shown in FIG. 13B in a manner similar to that shown inFIG. 12B. The approximation appears to be very good except for 100 p.u.water and H&H shale. The two extreme outliers correspond to heavy baritemud in the borehole (0 or 0.5 inch standoff). Therefore, one couldeasily apply this approach to an open hole neutron-gamma porositymeasurement. Similarly, this example can also be applied to loggingwhile drilling (LWD) measurements.

So far, the explanation of the present example has been limited to howthe two methods (detector gate and neutron burst timing to substantiallyeliminate the wellbore salinity effect and TRat₀ linear approximation toseparate the wellbore and formation response) work for the detectorcount rate ratio, which requires two or more gamma-ray detectors.Following will be explained how the two methods work for individualdetector count rates, which can be normalized by a neutron monitordetector. The individual detector count rate is defined as a sum of thetime spectrum, as shown in FIG. 7, within a certain detector timinggate. Since the neutron output of a neutron generator tends to vary as afunction of time in an unpredictable manner, the count rates are moreuseful if they are normalized by the neutron source output, e.g., thenumber of counts/10⁸ neutrons emitted by the source. The neutron outputcan be measured by a neutron monitor detector (not shown in the figures)disposed proximate the neutron source (see, e.g., U.S. Pat. Nos.6,754,586 and 6,884,994 incorporated herein by reference).

FIGS. 14A and 14B demonstrate the TRat₀ linear approximation forindividual detector count rates, i.e., the near (FIG. 14A) and far (FIG.14B) detectors. In this case, the denomination TRat₀ is not appropriatebecause there is no detector count rate ratio (not considering theexception of the normalization with the neutron monitor count rate). Thesame nomenclature is used for this method for consistency. For the neardetector count rate, a parameter x1 may be defined as the near countrate in the case of an 8-inch diameter wellbore having 5.5-inch ODcasing, with 4.95-inch casing ID, and fresh water in the wellbore. Thenear detector count rate is plotted for the same conditions except250-ppk water in the wellbore against x1 in FIG. 14A. The black line isthe 45-degree diagonal line and the green line is a linear fit throughthe data. The near detector count rate appears to be a linear functionof x1. Similarly, the far detector count rate may also be a linearfunction of variable x2, which is defined as the far count rate in thecase of an 8-inch diameter wellbore having 5.5-inch OD casing, with4.95-inch casing ID, and fresh water in the wellbore, as shown in FIG.14B. Although FIG. 14A and FIG. 14B only demonstrate linearity in oneborehole condition, the two count rates can be approximately written asa linear function of x1 and x2 in a wide range of realistic boreholeconditions, as shown in Equation 3. This is very similar to the TRat₀linear approximation for detector count rate ratios.

CountRate₁ =a ₁(BH)·x ₁ +b ₁(BH)

CountRate₂ =a ₂(BH)·x ₂ +b ₂(BH)  (3)

The timing gate for the count rates shown in FIGS. 14A and 14B may bethe same gate as the early TRat used previously in FIG. 8. It hasalready been explained when taking count rate ratio between twodetectors, it is possible to cancel the wellbore salinity effect.However, there will still be wellbore salinity effect in individualdetector count rates. In this case (using selected timing gates), theslopes or gains (a1 and a2 in Equation 3) may be functions of wellboresalinity but are very similar for the near and far detector count rateswith the condition of 250-ppk borehole water. The offsets (b1 and b2 inEquation 3) may also be functions of wellbore salinity but are verysmall compared to the count rates. Therefore, when taking a detectorcount rate ratio, it is possible to cancel the wellbore salinity effect,as shown in Equation 4. FIG. 15 confirms the detector count rate ratiobased on the two individual count rates (FIGS. 12A and 12B) isapproximately equal to TRat₀ (which is defined as the ratio of x1 andx2).

$\begin{matrix}{{TRat} = {\frac{{CountRate}_{1}}{{CountRate}_{2}} = {{\frac{{{a_{1}({BH})} \cdot x_{1}} + {b_{1}({BH})}}{{{a_{2}({BH})} \cdot x_{2}} + {b_{2}({BH})}} \approx \frac{{a_{1}({BH})} \cdot x_{1}}{{a_{2}({BH})} \cdot x_{2}} \approx \frac{x_{1}}{x_{2}}} = {TRat}_{0}}}} & (4)\end{matrix}$

Without suitably selected gate timing, the TRat₀ linear approximationcan still be applied to individual detector count rates. Similar toFIGS. 12A and 12B, FIGS. 16A and 16B demonstrate how the foregoing worksfor a late timing gate, which is from 130 μs after the last burst in thesequence shown in FIG. 7 to the end of the gamma ray decay to backgroundlevels. The individual count rates are still approximately a linearfunction of the parameter x (which is defined as the detector count ratein a predetermined standard borehole condition). Thus, for individualdetector count rates, the separation of borehole and formation responseis possible for any timing gate based on the linear model (Equation 3).A possible disadvantage of using individual detector count rate(relative to detector ratio) is that the wellbore salinity effect cannotbe canceled by optimizing the timing gate. The gain and offset (a and bin Equation 3) are function of wellbore conditions including wellboresalinity. Thus, this approach may require more complex corrections.

FIG. 17 shows that the slopes for the two individual count rates are notclose and the offsets are not always small for a late timing gate. Thus,when taking ratios, one can not only not cancel the wellbore salinityeffect, but also note that TRat is not a linear function of TRat₀ asshown in FIG. 17. However, one may use Equation 5 to describe the TRatresponse and separate the borehole and formation responses. In thiscase, one cannot define a parameter TRat₀ in a standard wellborecondition, but one can define two parameters x1 and x2 as the twoindividual detector count rates in a standard borehole condition. TRatis a function of x1 and x2, but the model is not linear. The two gains(a1 and a2) and two offset (b1 and b2) are functions of boreholeconditions including borehole salinity. This basically is a modifiedTRat₀ linear approximation method. Similar principles can still beapplied but they may be more complex. BH in Eq. (5) represents thewellbore conditions under which a and b are determined.

$\begin{matrix}{{TRat} = \frac{{{a_{1}({BH})} \cdot x_{1}} + {b_{1}({BH})}}{{{a_{2}({BH})} \cdot x_{2}} + {b_{2}({BH})}}} & (5)\end{matrix}$

The invention is described with reference to an example with two axiallyspaced apart gamma-ray detectors. In other examples, more than two gammaray detectors at different axial spacings may be used.

Example implementations of the two foregoing processes will now beexplained with reference to FIGS. 18-22. FIG. 18 shows a single neutronsource burst sequence, e.g., with burst duration of about 20 μs and waittime between bursts of about 30 μs. After a selected number of bursts ina sequence, the source is switched off until the gamma ray counting ratehas decayed essentially to background radiation levels. In one examplethe time interval after the last burst may be about 1000 μs before theinitiation of the next burst sequence. Gamma rays may be detected inselected time intervals, e.g., during the wait time between successiveneutron bursts and in the time interval between the last burst and theinitiation of the next burst sequence. The lower part of FIG. 18 showsthat the burst/wait time sequence 42 may be repeated a number of timesto enhance statistical precision.

Referring to FIG. 19, the numbers of detected gamma rays may then besummed or stacked over all the detection time gates, as shown at 50. Thestacked, detected numbers of gamma rays over all the detection timegates may be used to calculate TRat. At 52, this is shown as the sum ofthe detected gamma rays in the time gate of the first detector dividedby the sum of the detected gamma rays in the same time gate of thesecond detector. Depending on the care with which the detection timegate is selected, the gamma ray counts may be substantially free ofeffects of wellbore salinity.

FIG. 20 illustrates the selected gamma ray detection time gates, wherein44C indicates a short delay after the end of the neutron burst anddetection 44A takes place after the end of each neutron burst. Timinggate 44B follows the end of the last neutron burst, separated by a shortdelay, and ends when the gamma ray detection has decayed essentially tobackground levels (e.g., 1000 μs from the end of the last neutron burstin the burst sequence). For the purpose of determining TRat the counts44B and in all gates 44A are summed. This represents the sum of theearly and late time detected gamma rays.

FIG. 20A shows example signal processing for the determination of thecounts that are being used to determined TRat using a practical welllogging instrument as shown in FIG. 1. The gamma-ray time decay spectrum70 may be acquired in a multichannel counter as a function of time inthe neutron pulsing sequence. The detector experiences dead time aftereach detection event, i.e. a time during which, it cannot detect anothergamma ray immediately following the event that is being processed. Inparticular, at high count rates this will lead to a counting loss, whichas is well known in the art requires a “dead time correction”. Followingthe acquisition, the counts in each time bin are corrected for dead time72. Next at 74, the contribution from gamma-rays not related to neutroncapture is subtracted. Those gamma-rays may be caused by the naturalradioactivity of the formation and by the activation of the formation,borehole or downhole tool by the transmutation of isotopes intoradioactive isotopes by neutron reactions. The natural and activationgamma-rays form a quasi-constant background, which is unrelated to thegamma-rays from neutron capture and the counts need to be removed fromthe total. The counts after the correction for dead time 72 and gammaray background 74 are summed over the time gates 76 indicated in FIG. 20and enter the TRat calculation 52 (FIG. 19).

In FIG. 21, at 52, TRat is calculated as explained above. At 54, thegain and offset of a linear function (the coefficients a and b in Eq. 2)can be determined according to wellbore conditions (such as wellborediameter, casing OD, casing weight, casing ID, gas filled wellbore,double casing, etc.). The values of the gain and offset may be used toconvert TRat to TRat₀, which is shown at 56. TRat₀ may be used tocalculate a hydrogen index (HI) at 58. HI is related to formationporosity after correction for formation lithology and fluid content inthe pore spaces of the formation.

Referring to FIG. 22, the stacked, detected numbers of gamma rays overall the detection time gates, shown at 60, may also be used to calculatean individual detector count rate without taking any ratio with othergamma detectors. The individual detector counts can be used to computethe formation hydrogen index, as shown at 66 in FIG. 22. Depending onthe care with which the detection time gates are selected, thecalculated individual detector count rate may be substantially free ofeffects of wellbore salinity. In reality, because the neutron sourceoutput varies, the individual detector count rate can be normalized by aneutron monitor measurement to cancel the effects of variation inneutron source output.

In FIG. 22, at 60, detected gamma ray counts in one time gate may besummed over all the bursts in the plurality of burst sequences (42 inFIG. 20) and the sums individually counted for each gamma ray detector.At 62, the gain and offset of a linear function (the coefficients a andb in Eq. 3) are determined according to wellbore conditions (such aswellbore diameter, casing OD, casing weight, casing ID, gas filledwellbore, double casing, etc.). At 64, the gains and offsets for eachdetector function and individual detector count rate may be input to Eq.3 to determine, for each gamma ray detector, a value of x. At 66 one ormore of the values of x may be used to determine hydrogen index. HI isrelated to porosity as explained above.

FIG. 23 depicts an example computing system 100 in accordance with someembodiments. The computing system 100 may be an individual computersystem 101A or an arrangement of distributed computer systems. Thecomputer system 101A may include one or more analysis modules 102 thatmay be configured to perform various tasks according to someembodiments, such as the tasks depicted in FIG. 23. To perform thesevarious tasks, analysis module 102 may execute independently, or incoordination with, one or more processors 104, which may be connected toone or more storage media 106. The processor(s) 104 may also beconnected to a network interface 108 to allow the computer system 101Ato communicate over a data network 110 with one or more additionalcomputer systems and/or computing systems, such as 101B, 101C, and/or101D (note that computer systems 101B, 101C and/or 101D may or may notshare the same architecture as computer system 101A, and may be locatedin different physical locations, for example, computer systems 101A and101B may be on a ship underway on the ocean or on a well drillinglocation, while in communication with one or more computer systems suchas 101C and/or 101D that may be located in one or more data centers onshore, aboard ships, and/or located in varying countries on differentcontinents).

A processor can include a microprocessor, microcontroller, processormodule or subsystem, programmable integrated circuit, programmable gatearray, or another control or computing device.

The storage media 106 can be implemented as one or morecomputer-readable or machine-readable storage media. Note that while inthe example embodiment of FIG. 23 the storage media 106 are depicted aswithin computer system 101A, in some embodiments, the storage media 106may be distributed within and/or across multiple internal and/orexternal enclosures of computing system 101A and/or additional computingsystems. Storage media 106 may include one or more different forms ofmemory including semiconductor memory devices such as dynamic or staticrandom access memories (DRAMs or SRAMs), erasable and programmableread-only memories (EPROMs), electrically erasable and programmableread-only memories (EEPROMs) and flash memories; magnetic disks such asfixed, floppy and removable disks; other magnetic media including tape;optical media such as compact disks (CDs) or digital video disks (DVDs);or other types of storage devices. Note that the instructions discussedabove may be provided on one computer-readable or machine-readablestorage medium, or alternatively, can be provided on multiplecomputer-readable or machine-readable storage media distributed in alarge system having possibly plural nodes. Such computer-readable ormachine-readable storage medium or media may be considered to be part ofan article (or article of manufacture). An article or article ofmanufacture can refer to any manufactured single component or multiplecomponents. The storage medium or media can be located either in themachine running the machine-readable instructions, or located at aremote site from which machine-readable instructions can be downloadedover a network for execution.

It should be appreciated that computing system 100 is only one exampleof a computing system, and that computing system 100 may have more orfewer components than shown, may combine additional components notdepicted in the example embodiment of FIG. 23, and/or computing system100 may have a different configuration or arrangement of the componentsdepicted in FIG. 23. The various components shown in FIG. 23 may beimplemented in hardware, software, or a combination of both hardware andsoftware, including one or more signal processing and/or applicationspecific integrated circuits.

Further, the steps in the processing methods described above may beimplemented by running one or more functional modules in informationprocessing apparatus such as general purpose processors or applicationspecific chips, such as ASICs, FPGAs, PLDs, or other appropriatedevices. These modules, combinations of these modules, and/or theircombination with general hardware are all included within the scope ofthe present disclosure.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the invention as disclosed herein.Accordingly, the scope of the invention should be limited only by theattached claims.

What is claimed is:
 1. A method for pulsed neutron well logging of asubsurface formation, comprising: irradiating the formation with aplurality of bursts of neutrons of a group of selected durations;detecting gamma rays resulting from interaction of the neutrons during agroup of selected time gates, the gamma rays detected at at least twoaxially spaced apart locations from a position of the irradiating; in acomputer, determining a ratio TRat of the sum of detected gamma rays ata first axial spacing to the sum at a second axial spacing; and in thecomputer, performing a borehole correction according to a functionrelated to the ratio TRat before converting the ratio TRat to a hydrogenindex or porosity of the subsurface formation.
 2. The method of claim 1,further comprising: in the computer, using the function to convert theratio to a pre-defined formation property TRat₀; and in the computer,determining a hydrogen index or porosity of the subsurface formationusing the TRat₀.
 3. The method of claim 1, further comprising: repeatingirradiating the formation and detecting gamma rays for a selected numberof times.
 4. The method of claim 1, wherein the function comprises alinear function.
 5. The method of claim 1, wherein the function is:TRat=f ₁(BH)·TRat₀ +f ₂(BH)  (1) wherein, f₁(BH) and f₂(BH) aredependent on borehole conditions, and independent of formationconditions.
 6. The method of claim 1, in which the group of selectedtime gates does not contain any time within a neutron burst.
 7. Themethod of claim 1, in which the group of the selected time gatescontains at least some early and late gamma ray counts.
 8. The method ofclaim 1, wherein the group of time gates, burst length, and number ofbursts are optimized to eliminate/reduce the borehole effect on theratio TRat.
 9. The method of claim 8, wherein the borehole effect isborehole salinity effect.
 10. A method for pulsed neutron well loggingof a subsurface formation, comprising: irradiating the formation with aplurality of bursts of neutrons of a group of selected durations;detecting gamma rays resulting from interaction of the neutrons during agroup of selected time gates, the gamma rays detected at at least twoaxially spaced apart locations from a position of the irradiating; in acomputer, determining a ratio of the sum of detected gamma rays at afirst axial spacing to the sum at a second axial spacing; in thecomputer, performing a borehole correction according to a function toconvert the ratio to a value independent from borehole conditions; andin the computer, using the converted value to determine a hydrogen indexor porosity of the subsurface formation.
 11. The method of claim 10,further comprising: repeating irradiating the formation and detectinggamma rays for a selected number of times.
 12. The method of claim 10,wherein the function comprises a linear function.
 13. The method ofclaim 10, wherein the function is:TRat=f ₁(BH)·TRat₀ +f ₂(BH)  (1) wherein, TRat represents the ratio ofthe sum of detected gamma rays at the first axial spacing to the sum atthe second axial spacing, TRat₀ represents the converted value, f₁(BH)and f₂(BH) are dependent on wellbore conditions, and independent offormation conditions.
 14. The method of claim 10, wherein the convertedvalue represents a pre-defined formation property.
 15. The method ofclaim 10, in which the group of selected time gates does not contain anytime within a neutron burst.
 16. The method of claim 10, in which thegroup of the selected time gates contains at least some early and lategamma ray counts.
 17. The method of claim 10, wherein the group of timegates, burst length, and number of bursts are optimized toeliminate/reduce the borehole effect on the ratio.
 18. The method ofclaim 17, wherein the borehole effect is borehole salinity effect.
 19. Amethod for pulsed neutron well logging of a subsurface formation,comprising: (a) irradiating the formation with a plurality of bursts ofneutrons of a first selected duration; (b) detecting gamma raysresulting from interaction of the neutrons during time intervals of asecond selected duration following each burst until the beginning of thelast burst in the plurality thereof, the gamma rays detected by adetector positioned at at least one axially spaced apart location from aposition of the irradiating; (c) detecting gamma rays following the lastburst for a third selected time interval, the third selected timeinterval beginning substantially at the end of the last burst in theplurality thereof and ending when gamma ray detection has decayedsubstantially to background level; (d) in a computer, summing numbers ofgamma rays detected in each of the time intervals; (e) in the computer,determining coefficients, based on wellbore conditions, of a linearfunction related to the summed numbers of gamma rays detected by the atleast one detector; and (f) in the computer, using the coefficients andthe summed numbers of gamma rays detected by the at least one detectorto determine a hydrogen index of the subsurface formation.
 20. Themethod of claim 19 further comprising: repeating (a), (b) and (c) for aselected number of times; in the computer, summing numbers of gamma raysdetected in each of the time intervals; in the computer, determiningcoefficients, based on wellbore conditions of a linear function relatedto the summed numbers of gamma rays detected by the at least onedetector; and in the computer, using the coefficients and the summednumbers of gamma rays detected by each detector to determine a hydrogenindex of the subsurface formation.